Page 953 – RTO Insider

March 26, 2021

Strong Bipartisan Support for Advanced Nuclear at Senate Hearing

Developing countries in Africa and Asia are making deals with Russia and China to build nuclear reactors because the U.S. is not in the game. Russia has been dumping cheap uranium into the U.S. market, decimating domestic supply chains. Five more nuclear reactors, totaling 5.1 GW of electric power, are slated to close this year because energy markets do not pay for nuclear’s value as carbon-free, reliable power.

The critical state of the U.S. nuclear industry — and its potential to provide clean, baseload power for domestic and global markets — were central themes for the Senate Energy and Natural Resources Committee’s hearing Thursday on next generation advanced nuclear reactors. The hearing also offered a rare example of bipartisan agreement, with both Democrats and Republicans supporting a key role for nuclear energy as the U.S. moves toward a clean energy economy.

Advanced Nuclear — Sen. Joe Manchin | *U.S. Senate*

Bipartisan support provided $75 million in the Energy Act of 2020, to fund the creation of a national uranium reserve, to help prop up the domestic supply chain. Federal dollars also furnished the $210 million in grant money the Department of Energy awarded last year for its Advanced Reactor Demonstration Program, with the goal of having two advanced reactors online by 2027.

But, committee chair Sen. Joe Manchin (D-W. Va.) said, “We still have a lot of work ahead of us. The public remains cautious about nuclear.”

Citing figures from the International Energy Agency, he said, “If countries continue to allow nuclear reactors to be prematurely shut down, it will be $80 billion a year more costly to meet emissions goals. … Lifetime extensions are cheaper than new builds and are generally cost competitive with other generation technologies. We cannot afford to let this carbon-free energy resource fade out.”

Advanced nuclear reactors to be deployed over the next decade “will be safer, smaller and more efficient. [They] will generate less nuclear waste,” said Sen. John Barrasso (R-Wyo.), the committee’s ranking member. They will also open “new market opportunities beyond the energy sector,” he said, for example, in the production of chemicals and hydrogen.

The Natrium advanced reactor being developed by TerraPower — one of two companies receiving DOE funds for demonstration projects — combines a sodium fast reactor and molten salt energy storage, said Chris Levesque, president and CEO of the Bill Gates-funded company. The combination of generation and storage can “deliver 500 MW of power for 5 ½ hours,” providing flexible, dispatchable power, said Levesque, one of four industry experts speaking at the hearing.

Addressing one of the key public concerns about nuclear, Levesque said, TerraPower’s technology is also implicitly safer than traditional nuclear plants. “Unlike conventional reactors, Natrium operates at atmospheric pressure, and its operating temperature is hundreds of degrees below the boiling point of the coolant. This greatly reduces the likelihood and, importantly, the severity of any accident.”

On the other critical issue of nuclear waste disposal, X-energy CEO Clay Sell said his company’s small, fast-reactor technology uses fuel that is enclosed in “ceramic encased material. It is a tremendous fuel form, but it’s an even better waste form. You don’t have to consider the kinds of degradation faced with metal-clad fuels. We never have to cool this waste in water; it’s just air-cooled.”

As the other company receiving DOE funding for a demonstration plant, X-energy can also store all nuclear waste on the plant site, Sell said.

A Dangerously Eroded Supply Chain

One of the main challenges for both traditional and advanced nuclear technologies is the erosion of a domestic uranium supply chain in the U.S. The need is particularly acute for the high-assay, low-enriched uranium (HALEU) that both X-energy and TerraPower’s advanced reactors use.

Sell and others spoke about America’s increasing dependence on Russian-controlled sources of uranium, despite the 1 billion pounds of uranium in known and likely deposits across the U.S.

“America is dangerously close to losing to losing our uranium fuel industrial base,” said Scott Melbye, president of the Uranium Producers of America. “We lack a domestic enrichment capacity free of the control of foreign powers. The sole U.S. conversion facility in Illinois has been idle since 2017 and will restart operations in 2023.”

Congress’s funding for a national uranium reserve was intended to stimulate domestic production, and Melbye said the DOE should begin purchasing uranium for the reserve this year. He also called on Congress to ensure the reserve receives full funding of $150 million per year for 10 years.

But progress on the uranium reserve remains slow, according to a spokesperson from the National Nuclear Security Administration, which is working with the DOE on a plan for the reserve.

“NNSA is coordinating with [the] DOE Office of Nuclear Energy to establish first steps and to develop a long-term plan for the Uranium Reserve,” the spokesperson said in an email to RTO Insider. More information would be shared as it becomes available, the spokesperson said.

The dependence on Russian uranium is also playing out in global markets where developing countries in need of power are turning to both Russia and China for nuclear reactors to power their emerging economies.

“Russia uses nuclear exports as a tool to exert foreign influence and reap significant economic benefits, with a claimed $133 billion in orders for foreign reactors,” said Amy Roma, a founding member of the Atlantic Council’s Nuclear Energy and National Security Coalition. Meanwhile, China is estimating a $145 billion pipeline for foreign projects, while the U.S. has been sidelined “with no orders for nuclear reactors abroad,” she said.

“While the U.S. has ceded the current [global nuclear market], we have a chance to regain it when it comes to the next generation of advanced reactors where we hold a significant innovation edge,” Roma said. “They are simple, scalable and safe and can be used for both power and nonpower applications. U.S. innovation, when properly supported, can stand up to state-backed competitors.”

Unrecognized Value

The 94 nuclear reactors currently online in the U.S. provide about 20% of the nation’s power, Sen. Barrasso said. The Tennessee Valley Authority’s three nuclear plants make up 42% of the electricity the agency delivers to rural communities across its seven-state service territory, CEO Jeffrey Lyash said.

TVA is currently working on a fourth reactor, the Clinch River plant, which it hopes to have online by 2032, Lyash said. But he added, “optimizing and extending the operating lifetime of our nuclear fleet [has] got to be a primary focus. We’ve already extended the lives [of TVA plants] from 40 to 60 years, and we will shortly extend to 80, perhaps 100.”

TVA President and CEO Jeffrey Lyash | *U.S. Senate*

The wave of plant closures across the U.S. is linked to the design of the wholesale markers, Lyash said, raising the controversial question of how to value the reliability and dispatchability attributes of a baseload fuel like nuclear. FERC voted down an effort by the Trump administration to provide higher compensation for baseload coal and nuclear plants in 2018.

On the state level, Public Service Enterprise Group has threatened to close its two nuclear plants in New Jersey if the state reduces the subsidies the plants now receive. (See Ohio Lawmakers Repeal Nuclear Subsidy for Energy Harbor.)

Lyash called on Congress to work with the states to find a solution. Nuclear “delivers reliability, cost effectiveness [and] carbon-free energy, and its dispatchability, fuel stability and security [are] unmatched, and, frankly, unrecognized in the organized markets,” he said.

“We have short term-focused energy markets,” Lyash said. “It’s a market design that does not value the number one attribute that nuclear power gives, which is 24-7 baseload, emissions-free generation. As a result, you’ve seen good plants producing power at a very low cost shut down.”

March 26, 2021January 28, 2024

ACORE: Lack of Interregional Tx Planning Slowing Wind, Solar Development

A lack of interregional transmission projects is stymying the growth of renewable resources in SPP, MISO and PJM, according to a new report released Thursday by the American Council on Renewable Energy.

The report, compiled by Concentric Energy Advisors, was based on interviews with stakeholders and other key market participants in the RTOs and is meant to identify improvements to transmission planning and increase renewable resource deployment.

The current local, regional and interregional planning processes in place are not optimally designed to identify the best methods for getting renewable resources to the market and on the grid, the report said, emphasizing the need for implementing transmission planning reform and moving toward a “centrally coordinated and integrated” planning process.

“America’s transmission system is in need of a 21st century makeover if we’re going to have any shot at achieving the level of renewable deployment necessary to address our climate challenge,” ACORE CEO Gregory Wetstone said. “The current transmission planning processes in these regions are not working to deliver the affordable clean energy that states, businesses and consumers are demanding.”

Report Findings

The report highlighted several key findings, including:

A “centrally coordinated” planning process is needed to identify locations where “untapped” renewable resources are located. The planning would integrate “realistic estimates” of future renewable energy production in the RTOs and allow for advanced technology solutions.
Interregional transmission planning should have either a national model that is “unified” among the RTOs/ISOs or have regional models with “sufficiently aligned planning objectives, assumptions, benefit metrics and cost allocation methodologies” to assess the benefits and costs of the transmission projects. Stakeholders told the analysts that using separate RTO planning models with varying methodologies causes issues in achieving transmission development.
The “reasonable” expectations of renewable resource expansion should be integrated into future assumptions in transmission planning studies, including forecasts of storage additions to the system and the retirement of fossil fuel plants. Stakeholders cited under-forecasting of renewable energy resources in future assumptions as a “significant obstacle” to transmission development.
Benefit metrics used to assess the comparable benefit of projects relative to costs should be expanded and standardized across the RTOs. Stakeholders said standardization of benefit metrics should be completed to promote interregional transmission development along the RTO seams.
The planning models should reflect the expected real-time operations and economic dispatch of generation resources. Stakeholders voiced concerns over the ability of the legacy transmission planning models used by the RTOs to identify transmission solutions that will reflect the likely dispatch of resources.
The competitive planning processes would benefit from more coordinated planning to identify places where renewable resources are located and create infrastructure solutions that address the optimal paths to markets. Respondents said the current competitive processes lead to little expansion as the transmission owners and RTOs have focused on local or reliability projects with short time frames.
Cost allocations for generator interconnection upgrades should be shared with load or other interconnecting generators and based on fair allocations of benefits. Renewable project developers said they can’t access the MISO, SPP and PJM markets because of the costs of network upgrades necessary for interconnection.

“This report shows that bigger-picture, coordinated transmission planning is critical to developing the kind of reliable power grid we need to support the growth of clean, affordable renewable energy going forward,” said Abigail Ross Hopper, CEO of the Solar Energy Industries Association.

Report Opinions

Heather Zichal, CEO of the American Clean Power Association, one of the co-sponsors of the report, said the U.S. is lagging behind other nations in updating the grid to provide the proper infrastructure for the future.

“Transmission development may not sound exciting, but it is absolutely essential to an affordable, reliable and clean electric system,” Zichal said. “American homes and businesses will win if we modernize our electricity transmission system by coming together to improve the planning and permitting process for these needed grid improvements.”

Julie Lieberman, senior project manager of Concentric and the lead author of the report, said the findings identified the areas where transmission planning processes in SPP, MISO and PJM could be upgraded to better integrate wind, solar and battery storage projects currently under development in the RTOs.

Lieberman said the primary challenge to interregional transmission planning is the “lack of alignment between each RTOs’ respective transmission planning frameworks.” She said the different perspectives of the RTOs and the importance placed on decarbonization and renewable integration also contributes to the challenge of interregional planning.

“Of the market participants we interviewed, there was very little confidence that we could reach consensus across the RTOs and states and build the necessary backbone transmission framework to optimize renewable resources in the time frame necessary to meet our individual state clean energy goals,” Lieberman said. “Most expressed that a centrally coordinated planning effort or national authority would be needed.”

March 26, 2021

ERCOT: In ‘Better Position’ for Summer Heat this Year

ERCOT released its preliminary seasonal assessment of resource adequacy (SARA) for the summer Thursday, saying power reserves “are in a better position” than they have been in recent years.

The Texas grid operator projects a summer peak demand of 77.1 GW, which would be a new record. Based on information provided by generation owners, ERCOT expects to have nearly 87 GW of summer-rated capacity available and a 15.5% reserve margin June through September. That is up from 12.6% a year ago and 8.6% in 2019, when the grid operator set its all-time demand peak of 74.8 GW.

Staff postponed the SARA for two weeks to incorporate new system stress scenarios and other design changes following February’s near crash of the ERCOT system. The assessment includes a new section that details more extreme scenarios that could lead to energy emergencies and the possibility of controlled outages.

In unusually frank language, the grid operator said the extreme scenarios consist of “combinations of high system risk assumptions derived from historical data, and while there is a low probability that they will occur, they would be high-impact events.”

Texas summer — ERCOT’s 25 GW of wind capacity adds to 63 GW of available thermal generation. | © *RTO Insider*

Last year’s final winter assessment, based on normal weather conditions during peak periods from 2004 through 2018, forecast a peak of 57.7 GW. ERCOT shattered that mark on Feb. 14 at 69.2 GW and would likely have set a new all-time peak had not 35 GW of generation dropped off later that evening. (See ERCOT: Record 5 GW of Installed Wind Capacity.)

The ensuing days-long outages have been blamed for 111 deaths.

“We recently experienced a terrible tragedy, and ERCOT is committed to working with legislators, regulators and stakeholders on how to prepare for more extreme outcomes moving forward,” said Woody Rickerson, ERCOT’s vice president of grid planning and operations. “We must strike a balance between communicating the possibility of these types of conditions and providing realistic seasonal expectations.”

The ERCOT system is built to handle Texas’ 100-degree summer weather and generators are typically built to maximize performance during the dog days of August. Pete Warnken, the grid operator’s manager of resource adequacy, said an extreme weather event during summer would likely not lead to emergency, as happened in February.

“It wouldn’t be as much of a problem as what happened this winter, where you had failures of equipment as well as the natural gas infrastructure,” Warnken said during a media call. “There are certainly risks involved, but it’s a different situation.”

“The data for this summer is based on what we know today,” spokesperson Leslie Sopko said. “It is also worth keeping in mind that we are anticipating record breaking demand on the system. Of course, we will closely monitor the situation as we move into the summer months.”

Baseload generation accounts for 63.4 GW of the operational capacity. ERCOT also expects to have nearly 25 GW of installed wind capacity (with capacity factor ranges of 19%-61%), 4.2 GW of solar capacity (with a peak average capacity factor of 80%) and 3.5 GW of switchable capacity (resources dispatchable to both ERCOT and SPP) on hand.

Another 11.2 GW of capacity — all but 895 MW of it wind and utility-scale solar — has executed generator-interconnection agreements and is expected to be available. Nearly 1 GW of battery storage is also available, but not included in summer capacity contributions.

“ERCOT will benefit from growth in generation resources, but forecasts are also showing another record-breaking summer on the demand side,” Rickerson said.

The grid operator also released its final spring resource adequacy assessment, which includes a 64.4 GW peak-load forecast.

The SARA report is based on an assessment of generation availability and expected peak demand conditions at the time it was prepared. It now includes synchronized generation that may be producing power but has not yet been approved for commercial operations.

The assessment considers expected generation outages that typically occur during each season for maintenance, as well as a range of generation outage scenarios and weather conditions.

ERCOT will release the final summer SARA in early May. It said the report will reflect the expected summer weather conditions, including developing drought conditions in west and south Texas.

March 26, 2021

Ohio Lawmakers Repeal Nuclear Subsidy for Energy Harbor

Ohio lawmakers this week voted unanimously to eliminate the $1.1 billion customer-paid subsidy they created in July 2019 to bail out the state’s two nuclear power plants then owned by a former FirstEnergy subsidiary that had filed for bankruptcy protection.

A spokesman for Energy Harbor, the company that emerged from the bankruptcy of FirstEnergy Solutions, did not return a phone message or an email seeking comment.

Gov. Mike DeWine (R) is expected to sign the legislation, House Bill 128, when it arrives on his desk, ending at least one legislative chapter in what federal prosecutors have called “likely the largest bribery, money-laundering scheme ever perpetrated against the people in the state of Ohio.”

Those prosecutors have alleged that former Ohio House Speaker Larry Householder (R) forced the passage of H.B. 6, creating the nuclear subsidy as well as subsidies for two 1950s coal plants operated by the Ohio Valley Electric Corp. (OVEC). It also created a $20 million temporary fund for a half dozen utility-scale solar farms previously approved but not yet built.

Ohio Nuclear Subsidy — The Perry nuclear plant in Ohio | *Nuclear Regulatory Commission*

The federal investigation involved FirstEnergy as well as Energy Harbor. FirstEnergy fired its CEO and four others following its own internal investigation. The company recently hired a new chief ethics officer. (See FirstEnergy Names Chief Ethics and Compliance Officer.)

Former U.S. Attorney for the Southern District of Ohio David DeVillers recently said a grand jury has resumed its investigation into Householder, already indicted along with four associates on racketeering charges, after shutting down in November because of the COVID-19 pandemic.

H.B. 128 eliminates only the nuclear subsidies. It does nothing to remove the OVEC subsidies, which have been estimated to be worth more than $700 million. And while the legislation keeps the temporary subsidy for the solar projects, it does not affect the state’s renewable portfolio standard, which the GOP leadership previously capped at 8.5% by 2026.

Nor does H.B. 128 restore customer-paid utility consumer energy efficiency programs.

“I don’t see those coming back, House Speaker Bob Cupp (R) said in a brief teleconference following passage of the bill late Thursday.

Cupp did say, however, that he expects Rep. Jim Hoops (R) to hold hearings on the issue of the OVEC subsidy.

In a statement issued a short time later, Cupp said the bill is one “that Ohioans can be proud of — one that retains carbon-free energy in the state, provides additional ratepayer protections and savings, and moves Ohio forward. This is sound energy policy.”

Although there was no debate on the House floor before passage of the bill, Rep. Kent Smith (D) urged passage but noted that the bill did not remove the OVEC subsidies. “I would hope that this chamber would bring that up in the remaining 21 months” of the legislative session, he said.

Rep. Dick Stein (R), a co-sponsor of the original version of H.B. 128, which would have also removed the subsidies for the solar projects, also recommended passage.

March 26, 2021

CPUC, CAISO Take Major Steps for Summer Reliability

The California Public Utilities Commission on Thursday instituted a package of demand response programs to promote sharper reductions in electricity usage during times of strained supply and ordered additional procurement to increase CAISO’s planning reserve margin.

The orders are intended to head off capacity shortages this summer and next like those that plagued the state last year. They apply to the state’s three large investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.

“This proposed decision directs PG&E, SCE and SDG&E to take up multiple actions to avert the potential need for rotating outages in the summers of 2021 and 2022 by adopting or modifying programs aimed at decreasing energy demand and increasing energy supply during peak demand and net-peak demand hours,” CPUC President Marybel Batjer said in Thursday’s voting meeting.

Shortages last summer occurred in the net-peak hour, after solar ramped down in the evening but demand remained high during heat waves.

CPUC summer — CPUC members listen to a presentation by President Marybel Batjer, bottom right, on demand response programs for summer. | *CPUC*

Meanwhile, CAISO on Wednesday approved changes to market rules and bolstered resource adequacy in response to problems identified in a root-cause analysis of the blackouts it ordered Aug. 14-15 during a brutal Western “heat storm.” Labor Day weekend last year also saw energy emergencies amid triple-digit temperatures across the West. (See CAISO Says Constrained Tx Contributed to Blackouts.)

The ISO moved its changes through at a record pace; the process for the stakeholder initiatives took just three months. The CPUC also fast-tracked its orders to implement them this summer, leaving some stakeholders and ratepayers dissatisfied with a process that designated diesel generators and other fossil fuel resources as emergency resources.

The commission heard about an hour of public comment Thursday morning, most of it critical of the package. The potential health impacts of fossil fuel emissions on low-income communities was a main concern.

Batjer acknowledged the commenters’ dissatisfaction in her remarks, saying commissioners also shared it.

“We came to where we landed in this proposed decision after many restless days and nights grappling with the question of what plans we should have prepared in the worst-case weather and reliability scenarios,” Batjer said. “Let me underscore there will be backup generation only if needed as a last resort,” and only during short periods when demand outstrips supply.

The commission ordered the IOUs to procure an additional 2.5% of capacity to increase the state’s planning reserve margin from 15% to 17.5%, a move requested by CAISO. The change represents an additional 450 MW each for PG&E and SCE and 100 MW for SDG&E.

The CPUC also enacted a new Emergency Load Reduction Program to lower demand during the peak and net-peak hours of emergencies.

“The pilot program will compensate customers for voluntarily reducing demand on the power system when called upon to do so by the CAISO in the event of a grid emergency,” the CPUC said in a statement. “This program will serve as a layer of insurance on top of existing resource adequacy plans and will give grid operators a new tool among the existing demand management programs to address unexpected power system conditions.”

The moves came on top of the CPUC’s November 2019 order to the IOUs to procure an additional 3,300 MW of capacity to compensate for summer deficiencies and its order in February for the IOUs to procure more incremental capacity that can come online to serve demand this summer. (See Summer Readiness Sought by CAISO, CPUC.)

CAISO Summer Readiness

CAISO’s Board of Governors approved two stakeholder initiatives — Market Enhancements for summer 2021 and the first phase of the ISO’s Resource Adequacy Enhancements.

The board plans to take up the second phase of the RA enhancements — which deal with unforced capacity, must-offer obligations, and export and wheel-through priorities — in April.

The market changes seek to increase incentives for hourly imports and provide more accurate pricing signals during times of tight supply. CAISO proposed the measures after its analysis showed prices in mid-August remained too low to attract imports and additional capacity. (See CAISO MSC Weighs Summer Market Changes.)

The RA changes will establish a minimum state of charge for battery storage resources, require generators to find substitute capacity in advance of planned outages and streamline the process by which new storage resources connect to CAISO’s grid. The ISO expects approximately 1,500 MW of new battery storage to come online by summer, bringing total capacity to around 2,000 MW. Storing excess solar during daylight hours is seen as key to preventing evening load shed. (See CAISO Readies RA Enhancements for Summer.)

“The enhancements are designed to better equip our energy markets and power grid for extreme weather, while complementing the efforts of California’s regulatory authorities and utilities to develop new clean energy resources,” CAISO CEO Elliot Mainzer said in a statement. “We are committed to strong collaboration with our many state and regional partners to achieve reliable system operations this summer and beyond.”

March 26, 2021January 26, 2025

Industry Unsold on NERC Virtualization Proposals

NERC’s proposed virtualization-related updates to its critical infrastructure protection standards are headed for another round of revisions after an extended public comment period revealed widespread industry skepticism about the planned changes.

Comments for Project 2016-02 (Modifications to CIP standards) closed on Monday following a 60-day posting. (See NERC Seeks Faster Pace for Standards Postings.) NERC’s Standards Committee voted to extend the standard 45-day comment period because of the scope of the project, with revisions proposed for 11 standards:

CIP-002-7 — Bulk electric system cyber system categorization
CIP-003-9 — Security management controls
CIP-004-7 — Personnel and training
CIP-005-8 — BES cyber system logical isolation
CIP-006-7 — Physical security of BES cyber systems
CIP-007-7 — Systems security management
CIP-008-7 — Incident reporting and response planning
CIP-009-7 — Recovery plans for BES cyber systems
CIP-010-5 — Configuration change management and vulnerability assessments
CIP-011-3 — Information protection
CIP-013-3 — Supply chain risk management

At January’s Standards Committee meeting, NERC Manager of Standards Development Soo Jin Kim explained that the standard development team (SDT) had more time than usual to add changes to the proposal because the project had been “lying in wait” because of active comment periods involving some of the same standards. As a result, the team decided to “put forth all of their modifications in [the same] package.”

Industry Warns of SDT Overreach

Project 2016-02 began in response to FERC Order 822, which directed NERC to modify the CIP standards to:

provide mandatory protection for transient devices used at low-impact BES cyber systems based on their risk to BES reliability;
require responsible entities to implement controls protecting communication links and sensitive BES data communicated between control centers; and
provide “needed clarity” to the definition of low-impact external routable connectivity.

Proposed updates include expanding the scope of CIP-002 and CIP-005 to apply to virtual machines, new requirements for the type of software to be used in vulnerability assessments before connecting physical or virtual cyber assets, and mandatory confidentiality and integrity protections for data passing between physical security perimeters. The team also put forward a number of new, modified or retired definitions for terms in NERC’s glossary, along with the implementation plan.

However, none of the proposed standards met the two-thirds segment-weighted threshold required for approval. Results ranged from 53.26% for CIP-009-7 to 26.30% for CIP-005-8.

A common criticism among industry stakeholders was that the team seemed to have focused on numerous small details involving virtualization and cloud devices while not paying the same amount of attention to how those pieces fit together into a broader whole. In a comment endorsed by several other respondents, the Midwest Reliability Organization’s NERC Standards Review Forum said the current standards “could be revised more efficiently to … ensure the virtualization security objectives are met, reduce the impact to entities’ programs and provide greater clarity to auditors.”

| Shutterstock

The Tennessee Valley Authority pushed on this theme as well, arguing that in trying to encompass all situations, the SDT may have inadvertently bound the new requirements to particular software and hardware architectures. In the rapidly changing world of technology, these specifications could rapidly become obsolete, TVA said.

“[We support] an approach that embraces innovative technologies that enhance security and reliability, [but] the proposed changes are myopic in requiring differentiation in virtualization technologies supporting [computer], network and storage resources,” TVA said. “These distinctions are becoming increasingly indistinguishable as virtualization technologies evolve. Modern standards should make no distinctions in the treatment thereof, so as not to preclude adoption of emergent technology.”

While other respondents were more understanding of the need for detail, worries remained about the level of complexity in the new standards, reflected in the proliferation of language dealing with various types of access and control systems, broken down further into virtual and physical versions. Duke Energy suggested that the team either pursue further revisions to ensure “a coherent approach to compliance,” or pare back the changes in the interest of consistency with prior terminology.

“SDT’s approach solves certain problems with virtualization, but in doing so, creates discrepancies in how the standards are applied between traditional and newer technologies,” Duke said. “The creation of additional ‘device types’ while not resolving the overall inconsistency in treatment of devices … may confuse entities and auditors.”

March 26, 2021November 2, 2023

Rural Ohio Lawmakers Want Towns to Have Final Say on Renewables

The battle waged by some Ohio Republican lawmakers for more than a decade to limit wind and solar development is back on the front burner, this time with the support of some rural voters who say the decisions of the state’s Power Siting Board (PSB) on utility-scale projects should be put to a vote at the township level.

A pair of bills introduced last month both in the House of Representatives and Senate to give townships the last word on renewable projects had their third public hearings before utility committees this week and are expected to quickly move to floor votes.

House Bill 118, introduced Feb. 16 by Northwest Ohio Reps. Dick Stein (R) and Craig Riedel (R), has been presented as a way for local government to pull back control of renewable projects from the PSB, characterized as distant and paying little attention to local issues in proponent testimony earlier this month. Senate Bill 52, introduced Feb. 9 by Sens. Bill Reineke (R) and Rob McColley (R), both also representing the state’s northwest, takes a similar tack.

But an unexpected surge of opposition orchestrated by the solar industry to the bills, buttressed by pro-solar farmers worried about the politicization of their property rights in ballot fights, appears to have stalled momentum on the legislation.

Well over 120 people, including farmers, school districts administrators, economic development organizations and solar developers, logged objections to the proposed legislation this week. The committee hearings, which lasted nearly five hours each, ended with neither votes nor an announcement of further hearings.

GOP leadership has successfully reduced Ohio’s renewable mandate since it was initiated in 2008 at 12.5% by 2025, to 8.5% by 2026. A second, abolished mandate required another 12.5% of power sold in Ohio by 2025 to be generated by “advanced energy” technologies, including fuel cells and advanced nuclear plants.

Renewables generated about 5% of the power produced in Ohio in 2019, according to the Public Utilities Commission, using data from PJM. About 2.5% of that was wind-generated.

Wind development has been stymied since 2014 when GOP leadership, participating in an 11th hour conference committee preparing the state budget, slipped language into the final legislation extending the distance a wind turbine must be from adjacent properties that are not part of a wind development.

But the pace of solar development, especially large utility-scale projects, has accelerated in recent years. Currently there are 23 applications totaling 4,279 MW pending before the PSB. The agency has already approved another dozen projects with a total generating capacity of more than 2,000 MW.

The growth of solar, typically welcomed by local schools and government because of the millions of dollars in guaranteed long-term payments they bring for up to 40 years, appears to have prompted the proposed legislation — as well as the pushback against it.

Michael Lutmer, who owns a farm in Highland County in southwest Ohio, summed up his disgust with the legislation in testimony before the House Public Utilities Committee: “I was surprised to read the bill sponsors believe they are ‘allowing citizens of a township the ability to exercise their property rights through a public referendum with regards to solar projects.’ What’s next, where I can park my truck, build my barn or how big my house can be?

“The property rights referred to in HB 118 are held by the person who writes the mortgage check,” Lutmer said. “As a farmer, I take on all the risk brought by Mother Nature. Diversification into a solar project represents a unique opportunity to supplement my volatile farming income with an income stream that is fixed over the life of the project. This is simply a good business practice.”

On March 9, another farmer, Joanna Clippinger of Preble County, also told the committee that she was a strong believer in private property rights. For that reason she supported HB 118 to allow local voters an up or down vote on the huge solar projects.

“My husband is a full-time farmer, and our livelihood depends on the productivity of our land. Yes, my neighbor certainly has property rights, but so do we,” she said, adding that her family has owned and farmed the property for more than 100 years.

Clippinger said she had to hire a lawyer to intervene in a case before the PSB for a 1,000-acre solar farm adjacent to her farm after learning that elected officials had little say over the project. “I had to spend thousands of dollars to hire a lawyer for someone in our government to hear my opinion. That goes against the very principles of democracy,” she said.

“I personally have many concerns about a large-scale solar facility being built next to me. However, if I knew, through a ballot initiative, that the majority of my fellow township residents supported its construction, I would be willing to accept the will of the people in my community. This bill embodies my core political beliefs: property rights, small government and, most importantly, local control,” she told committee members.

The Utility Scale Solar Energy Coalition of Ohio, a relatively new trade group organized by solar developers to answer the charges that developers and the PSB ignore the complaints of farmers who oppose solar farms, led the coordinated testimony opposing the legislation.

“In Ohio, data centers like Amazon, Facebook and Google are buying the energy from entire solar projects in an attempt to meet their sustainability goals,” Jason Rafeld, executive director of the coalition, told the committee. “Solar developers are racing to meet skyrocketing demand for clean energy, uniquely positioning the state to benefit for decades.

“If this opportunity is realized, the state will become a solar powerhouse, bringing thousands more jobs and billions of critically needed investment dollars and economic growth to municipalities.”

Others pointed out that the solar installations, which leave no permanent structures behind when they are decommissioned, are a way to give the farmland a rest. One witness noted that in some regions farmers have allowed sheep to graze between the rows of solar panels.

Jared Wren, a development associate with Hecate Energy, a global solar development company with projects under development in Ohio, including a 300-MW solar farm that will be built in Highland County, described the PSB licensing process as “fact-based, robust, rigorous and equitable.”

“When I am discussing solar development with folks in a project area, either around the kitchen table or standing outside around my pickup truck in the driveway, there are a few concepts that I work very hard to convey,” he said.

“First of all, that my company, and the project we intend to develop, is not a nameless, faceless entity, attempting to approach by stealth and drop a project next door without their knowledge. In fact, it is quite the opposite. I am there to give a face and a name to the projects and let folks know that I am there to hear their concerns, that I understand and respect their property and way of life,” he said.

Both Wren and competitor Mike Volpe, vice president at Open Road Renewables, another solar developer working in Ohio, noted that getting through the PSB process typically takes 12 to 16 months and that their companies typically spend money months before they even file an application with the agency.

Volpe said Open Road’s first Ohio project, the 200-MW Hillcrest project in Brown County, now nearly complete, will pay $1.8 million annually to local schools and government. He said Open Road hired 400 Ohio-based workers to build the solar farm.

Both developers also noted that they already contact local governments before they file applications with the PSB.

March 26, 2021November 2, 2023

Vt. Bill Seeks $3,000 EV Incentive for Low-income Residents

The Vermont House of Representatives on Tuesday passed a transportation bill that would allocate $1.5 million to help low-income residents replace older cars with clean transportation.

The bill (H.433) would create the Replace Your Ride Program to give a $3,000 incentive to Vermonters who qualify as low income and demonstrate they are removing an internal combustion car from the roads. The bill was approved unanimously in the House, where Democrats and Progressives hold a 38-12 edge over Republicans. It now moves to the Senate, where Republicans are outnumbered 23-7.

Proponents of the program, which is modeled after a program in California, believe it will help Vermont address transportation poverty, Linda McGinnis, policy analyst fellow at Energy Action Network, said during a recent Sierra Club-hosted webinar.

Participants could use the incentive to purchase a new or used EV, an all-electric bike or motorcycle or use shared mobility services.

A broad group of organizations has supported a six-person steering committee in developing the program during the last year. McGinnis co-chairs that committee.

“We want lower-income Vermonters to be able to choose the type of clean transportation option that fits their needs,” McGinnis said. “Some may want to stick with the car because they live in rural areas, while others may really be thinking about trying to go carless.”

The transportation sector accounts for 45% of Vermont’s carbon emissions. That number is growing because Vermonters travel more miles per person than residents of other Northeast states, and they “have a taste for larger vehicles,” she said. In addition, 54% of the vehicles on the road are more than nine years old.

The poorest Vermonters, McGinnis said, spend up to 25% of their income filling up their cars with gasoline.

“That’s a pretty radical figure,” she said.

The Replace Your Ride program would make it feasible for low-income residents to purchase an EV and take advantage of lower operating costs in the future.

“The average rural Vermont driver … stands to save about $1,900 a year from driving an EV,” she said.

The program is also designed to stack with other incentives. Combining the Replace Your Ride incentive with utility, state and federal programs could reduce the price of a car by up to $17,000, McGinnis said.

Additional funding will be necessary to build out the program. McGinnis said that the program would be a good fit for funds that will come from emissions allowance auctions in the Transportation Climate Initiative Program beginning in 2023. (See TCI Releases Draft Rule for Cap-and-Invest Program.)

EV Charging

The transportation bill also would authorize funding to support EV charging infrastructure development and require utilities to adopt EV charging rates.

As proposed, the state’s Agency of Transportation would create a $1 million pilot program to support installation of EV charging equipment at multiunit dwellings. The pilot would expand on work already completed with Volkswagen settlement funds.

In addition, all Vermont electric distribution utilities would be required to implement EV charging rates by June 2024. The rates, which would be subject to regulatory approval, would encourage EV use and avoid negative impacts on ratepayers who do not have EVs.

March 25, 2021November 28, 2023

Report Finds Virginia State Agencies Lagging on Environmental Justice

Implementing Virginia’s ambitious environmental justice goals could cost the state millions of dollars and require hiring dozens of new full-time employees, as well as consultants, according to a new report from the Interagency Environmental Justice Working Group.

The 44-page report did not specify a dollar amount, but a majority of the 35 state agencies covered in the study said additional funding and time would be needed for them to create and implement robust environmental justice policies. An estimated 34 new full-time positions spread over 24 state agencies would also be required, the report said.

“This report represents an important first step towards securing justice for disadvantage communities that have been disproportionately burdened by the impact of climate change,” Gov. Ralph Northam said in a statement released with the report.

The report and the formation of the working group were mandated as an addendum to Virginia’s Environmental Justice Act, signed into law by Northam last year. The law calls on state government to incorporate environmental justice considerations into policy and decision making affecting low-income and disadvantaged communities.

Some of the report’s key findings included:

- - Six agencies identified a need for internal assessments of environmental justice-related regulations and policies to develop a baseline level of understanding, including the Virginia Marine Resources Commission, Department of Wildlife Resources and Department of Historical Resources.
  - Six agencies also reported they would need a third-party consultant to complete an environmental justice study, including the Office of the Secretary of the Commonwealth and Virginia Economic Development Partnership.
  - Each agency assessment will cost between $50,000 and $100,000, and some agencies reported they would need more than two years to comply with the law.

The law defines environmental justice as “the fair treatment and meaningful involvement of every person, regardless of race, color, national origin, income, faith or disability, regarding the development, implementation or enforcement of any environmental law, regulation or policy.”

The working group included top officials from about a dozen state agencies and the governor’s office. The group met four times in October and November 2020 to produce the report, assessing each agency on environmental justice performance in policy and regulations, community engagement and involvement, economic development and infrastructure, and fiscal impact and resources.

Checking Boxes

Based on the report, different state agencies are clearly at different points in their awareness and action on environmental justice issues. The Department of Wildlife Resources, for example, said that while it hired a director of diversity and inclusion in 2018, it “does not have agency-specific environmental justice policy currently in place”; nor has it done a full analysis of the policies and regulations that would be needed.

Meanwhile, the Department of Transportation, the state’s largest agency, does have environmental justice guidelines to provide its various divisions “with a consistent framework for both preparing an EJ analysis and developing an effective public involvement strategy.” However, actual implementation across the department is uneven.

The Department of Environmental Quality is farthest along in its efforts. The agency hired an outside consultant in 2019 to produce a study and recommendations on how to incorporate environmental justice principles into its planning and programs.

In the report the department says, “Success in advancing environmental justice through DEQ’s activities won’t simply involve ‘checking boxes,’ but rather putting a process in place to build trust, share understanding and align values among community members, stakeholders, local state and federal government, industry partners and DEQ staff.”

State-level Action

The report’s primary recommendation is to make the working group an ongoing body with public hearings in which it can gather input from environmental justice communities. The group would work with the Virginia Council on Environmental Justice and the Office of Diversity, Equality and Inclusion, and continue to produce annual reports on the state’s environmental justice performance.

“While an environmental justice assessment is not applicable for every Virginia state agency, the continuation of collaboration across state agencies, with leadership by environmental protection agencies, is beneficial to the continued progression of environmental justice policy in the commonwealth,” the report says.

Virginia is one of a growing number of states that have either enacted or are considering environmental justice laws. According to a recent analysis by Bloomberg Law, environmental justice statutes are on the books in 10 states and pending in 13. On the federal level, President Biden’s executive order on climate change included a Justice40 provision, requiring 40% of all benefits from government investments benefit disadvantaged communities, with results tracked on an Environmental Justice Scorecard. A federal Environmental Justice for All Act was introduced in the House in 2020 but never got beyond committee hearings.

March 25, 2021November 2, 2023

Act on Climate Heads to RI Gov.’s Desk

A bill that sets a legally binding 2050 net-zero emissions target for Rhode Island is headed to Gov. Daniel McKee for his signature.

The House of Representatives passed the Act on Climate (House Bill 5445A) 53-22 on Tuesday, following Senate passage of an identical bill (Senate Bill 87A) last week.

The bill updates the state’s emission-reduction targets to 45% below 1990 levels by 2030 and 80% by 2040. The state’s Executive Climate Change Coordinating Council would be directed under the law to create plans to reduce emissions and coordinate them through state agencies. The law would further authorize residents or entities to sue the state if it is not fulfilling any part of its duties as laid out in the act.

Representatives from both sides of the aisle introduced a flurry of amendments to address concerns about the bill’s language governing the climate council’s broad regulatory authority and the right to sue. None of them were passed during a nearly four-hour debate.

House Minority Leader Blake Filippi (R) introduced an amendment to ensure that all plans created by the climate council would be returned to the legislature, which would consider the plans’ merits and pass laws accordingly.

He said it was “legally questionable” whether the legislature could delegate broad regulatory power to the executive branch via the climate council to be used to regulate the actions of residents.

“That’s our job,” he said. “It’s our responsibility.”

House Majority Leader Rep. Christopher Blazejewski (D) argued that the amendment was “untethered from reality.”

“We pass laws, and then the administration promulgates regulations through a public process called the Administrative Procedures Act,” he said. “It happens all the time.”

Rep. Patricia Morgan (R) introduced an amendment to remove the right-to-sue clause.

Giving anyone in the state the ability to sue would be “financially crushing,” Morgan said. “This is the mechanism by which, even if it’s not possible to meet the goals of the plan, the people who live in the state will pay.”

Deputy Majority Leader Jason Knight (D) argued against the amendment, saying that the right of enforcement only applies to whether the state fulfilled the duties required under the law. Nobody, he said, can sue for damages or because they wish the council’s plans were different.

Equity Concerns

The bill includes directives that the climate council’s plan will ensure an equitable transition to compliance for environmental justice communities.

Rep. Anastasia Williams (D) said she could not support the language of the bill and would not vote in favor of passage. She said that language directing the council to “identify” support for workers and “provide” for the development of programs in a manner that addresses inequity is no longer appropriate.

“For years … this body has been making plans and studies to ‘identify,’” Williams said. “We don’t need to do that anymore.”

She said she was standing up to represent the people who have been oppressed in the state.

“If you expect me to vote on this bill the way it’s written without making sure that it’s mandated that we will be part of the plan, not just be identified in the plan, I’m not,” she said.

There were no amendments that sought to change the equity language of the bill.